Power utilities generate electrical power at remote plants and deliver electricity to residential, business or industrial customers via transmission networks and distribution grids. Power is first transmitted as high voltage transmissions from the remote power plants to geographically diverse substations. From the substations, the received power is sent using cables or “feeders” to local transformers that further reduce the voltage. The outputs of the transformers are connected to a local low voltage power distribution grid that can be tapped directly by the customers. The power distribution grids may be configured as either radial or networked systems. A radial distribution system includes a number of feeder circuits that extend radially from a substation. Each circuit serves customers within a particular area and the failure of a radial circuit cuts off electric service to the customers on that circuit. In a networked distribution system, service is provided through multiple transformers connected in parallel, as opposed to the radial system in which there is only one path for power to flow from the substation to a particular load. A networked distribution system provides multiple potential paths through which electricity can flow to a particular load. By its nature, a networked distribution system is more reliable than a radial distribution system. When a networked distribution system is properly designed and maintained, the loss of any single low or high voltage component usually does not cause an interruption in service or degradation of power quality. Network protection devices or switches automatically operate to isolate the failed component. Networked distribution systems are installed in high-load density metropolitan areas (e.g., Chicago and New York City) that require reliable electricity service.
FIG. 1 shows the conventional infrastructure 100 associated with delivering electrical power to residential, business, or industrial customers. Infrastructure 100 may be viewed as having four primary sections, namely, generation 110, transmission 120, primary distribution 130, and secondary distribution 140. Generation 110 involves a prime mover, which spins an electromagnet, generating large amounts of electrical current at a power plant or generating station. Transmission 120 involves sending the electrical current at very high voltage (e.g., at hundreds of kV) from the generating station to substations closer to the customer. Primary distribution 130 involves sending electricity at mid-level voltage (e.g., at tens of kV) from substations to local transformers over cables (feeders). Each of the feeders, which may be 10-20 km long (e.g., as in the case of Consolidated Edison Company of New York, Inc.'s (Con Ed's) distribution system in New York City), supplies electricity to a few tens of local transformers. Each feeder may include many feeder sections connected by joints and splices. Secondary distribution 140 involves sending electricity at nominal household voltages from local transformers to individual customers over radial or networked feeder connections.
In metropolitan areas (e.g., New York City), the feeders run under city streets, and are spliced together in manholes. Multiple or redundant feeders may feed through transformers the customer-tapped secondary grid, so that individual feeders may fail without causing power outages. For example, the electrical distribution grid of New York City is organized into networks, each composed of a substation, its attached primary feeders, and a secondary grid. The networks are electrically isolated from each other to limit the cascading of problems or disturbances. Network protection switches on the secondary side of network transformers may be used for isolation. The primary feeders are critical and have a significant failure rate (i.e., a mean time between failures of less than 400 days). Therefore, much of the daily work of the power company's field workforce involves the monitoring and maintenance of primary feeders, as well as their speedy repair on failure.
Multiple or redundant feeders may feed the customer-tapped grid, so that individual feeders may fail without, causing power outages. The underground distribution network effectively forms at least a 3-edge connected graph—in other words, any two components can fail without disrupting delivery of electricity to customers. Most feeder failures result in automatic isolation—so called “Open Autos” or O/As. When an O/A occurs, the load that had been carried by the failed feeder must shift to adjacent feeders, further stressing them. O/As put networks, control centers, and field crews under considerable stress, especially during the summer, and cost millions of dollars in operations and maintenance expenses annually.
Providing reliable electric supply requires active or continuous “control room” management of the distribution system by utility operators. Real-time response to a disturbance or problem may, for example, require redirecting power flows for load balancing or sectionalizing as needed. The control room operators must constantly monitor the distribution system for potential problems that could lead to disturbances. Sensors may be used to monitor the electrical characteristics (e.g., voltage, current, frequency, harmonics, etc.) and the condition of critical components (e.g., transformers, feeders, secondary mains, and circuit breakers, etc.) in the distribution system. The sensor data may guide empirical tactics (e.g., load redistribution in summer heat waves) or strategies (e.g., scheduling network upgrades at times of low power demand in the winter); and provide indications of unique or peculiar component life expectancy based on observations of unique or peculiar loads. Power companies and utilities have developed models for evaluating the danger that a particular feeder or other network component could fail. The models, which are based on traditional statistical techniques such as linear regression analysis, provide likelihood of network failure or jeopardy scores, which may be used to prioritize component testing (e.g., high voltage isolation testing (“Hipot testing”)), network repairs, maintenance or reinforcement. However, in practice, the scores obtained using the current models are a weak guide and provide only a rough indication of likely failure events.
Consideration is now being given to improving prior art systems and methods for management of an electrical power distribution system. Attention is being directed to applying machine learning to the development of short-term and long-term strategies for operating the electrical power distribution system to provide reliable electric service.